Natural gas is a combustible, gaseous mixture of several different hydrocarbon compounds now often extracted by fracking from underground reservoirs within porous rock. The hydrocarbon constituents of natural gas vary depending on the geographic location of the reservoir and even locally where the composition of gas extracted from a single source can vary. Regardless of any variations, however, the primary component of natural gas is methane, a colorless, odorless, gaseous saturated hydrocarbon. Methane usually accounts for 80% to 95% of any natural gas sample and the balance is composed of varying amounts of ethane, propane, butane, pentane and other hydrocarbon compounds. Some extracted natural gas may contaminated with small amounts of impurities that require detection and removal. Sour gas can comprise trace contaminants such as, Mercury (Hg), Hydrogen sulfide (H2S), Carbonyl sulfide (COS), Mercaptans (RSH), and aromatic compounds including those from the group known as BTEX (Benzene, Toluene, Ethylbenzene and Xylene).
Natural gas is used extensively in residential, commercial and industrial applications. It is the dominant energy used for home heating with well over half of American homes using natural gas. The use of natural gas is also rapidly increasing in electric power generation and as a transportation fuel.
Natural gas is commercially measured by the amount of energy it contains. The common unit of measurement in the United States is the British Thermal Unit (BTU). One BTU is equivalent to the heat needed to raise the temperature of one pound of water by one-degree Fahrenheit at atmospheric pressure. A cubic foot of natural gas has about 1,027 BTU (1083.54 kilojoules (kJ)). Natural gas is normally sold from the wellhead, i.e., the point at which the gas is extracted from the earth, to purchasers in standard volume measurements of thousands of cubic feet (Mcf). However, consumer bills are usually measured in heat content or therms. One therm is a unit of heating equal to 100,000 BTU (105,505.59 kJ).
Three separate and often independent segments of the natural gas industry are involved in delivering natural gas from the wellhead to the consumer. Production companies explore, drill and extract natural gas from the ground; transmission companies operate the pipelines that connect the gas fields to major consuming areas; and distribution companies are the local utilities that deliver natural gas to the customer.
In the United States alone, natural gas is delivered to close to 200 million consumers through a network of underground pipes that extends over a million miles. To produce and deliver this natural gas there are over a quarter-million producing natural gas wells, over one hundred natural gas pipeline companies and more than a thousand local distribution companies (LDCs) that provide gas service to all 50 states.
Pipeline companies transport gas from sellers, such as producers or marketers, to buyers, such as electric utilities, factories and LDCs. LDCs can choose among a variety of sellers of natural gas and customers may choose its LDC supplier. The consumer's LDC, as the owner/operator of the distribution network, delivers the gas to the consumer, but the LDC only charges the consumer for delivery of the gas and the independent supplier bills for the gas. Not only upon extraction form the ground but at each of the stages of custody transfer, energy content analysis provides critical value information to the purchaser.
An important part of the art in gas sample conditioning relates to the process of vaporization of a liquid sample extracted via a probe from a gas pipeline or source. Once the liquid sample is extracted, it is typically communicated from the take-off probe through a corrosion-resistant super alloy, such as stainless-steel tubing, with a relatively small diameter to a sample conditioner for vaporization, pressure regulation, and ultimately to an analyzer, such as a chromatograph, for analysis.
The distance between the liquid probe takeoff and the analyzer often exceeds 30 feet (9.144 meters) and may even exceed 100 feet (30.48 meters). When, as is typical, the extracted liquid sample is vaporized proximate to the probe, the vaporized sample must move physically from the probe at a high pressure, e.g., 2000 psig (13789.51 kPa), to the analyzer while preserving the vapor stage and being subject to substantial pressure reduction to a relatively low-pressure zone, e.g., 10-30 psig (68.9 kPa-206.8 kPa), which is an acceptable pressure for a typical analyzer/chromatograph. During the process, it is important to avoid cooling the vapor to a point near the vapor phase curve to minimize the risk of hydrocarbon dew point dropout in the form of condensation.
If such condensation occurs, then the input to the analyzer/chromatograph is fouled with liquid. Introduction of such liquid invariably compromises the integrity of and damages the chromatographic packing by column bleed, that will, at best, result in generation of false readings from ghost peaks, etc., and at worst, destroy the analyzer. Consequently, introduction of liquids into the chromatographic analyzer results in economic harm, at best, from false readings, and at worst, decreased system operational efficiency attributable to taking the fouled unit off-line either for complete replacement or for restoration to an operationally acceptable condition.
Accordingly, it is important to maintain the integrity of the vaporized liquid sample, without any phase change, for the entire period from flash vaporization to the time of analysis.
Particularly in the case of hydrocarbon vapor analysis, the issue of hydrocarbon dew point dropout in gas sampling has been addressed. Dew point dropout or phase transition of an extracted pipeline sample is prevented by maintaining adequate post-vaporization heating of pressure regulators, gas lines, and other components, with which the sample gas come into contact following vaporization, during communication to a downstream analyzer/chromatograph or vapor sample collection vessel. Maintaining pressure and temperature of the vaporized sample beyond its dew point-phase transition envelope, whether the sample comprises a heterogeneous mixture of components possessing a range of vapor condensation lines or a substantially homogeneous composition with a more predicable phase envelope curve such as LNG, prevents the vapor gas sample from reverting to a liquid.
Natural gas sampling systems, however, are typically located in harsh environments, e.g., where outdoor ambient temperatures can be significantly below the gas dew point temperature and where dangerous explosion-prone gas vapors are often permeating into the surrounding atmosphere. Accordingly, any heating mechanism used must adhere to strict standards in order to generate enough heat to overcome the low ambient temperature while doing so without exposing or releasing the gas samples gases to atmosphere and avoiding safety problems, caused by exposure of vaporized sample gas to electrical wiring, etc.
The American Petroleum Institute (API) has suggested using catalytic heaters to maintain temperature stability of extracted samples to avoid undesirable temperature changes to the gas sample communicated between a source, e.g., pipeline and the analyzer. Catalytic heaters of the type referred to by the API in its Manual of Petroleum Standards call for heating a sample gas stream throughout a selected portion of a system where the heated sample is then introduced into the analyzer at an acceptable pressure. One preferred system for achieving proper system thermal stability employs heat tracing to insure substantially uniform temperature maintenance over the entire length of the vaporized sample pathway during sample communication from take-off to the analyzer. Such performance is achieved with use of a P53 Sample Conditioning System available from Mustang Sampling, LLC of Ravenswood, W. Va. and embodiments disclosed and described in U.S. Pat. No. 7,162,933, the entirety of which is herein incorporated by reference.
Turning to issues associated with vaporization itself, vaporization devices in which a low carbon number hydrocarbon liquid, such as natural gas liquid (NGL) and particularly cryogenic LNG, is vaporized by heating may suffer from development of temperature gradations proximate to a liquid sample entry port. In the case of such temperatures exceeding the heat of vaporization, pre-vaporization of the liquid sample may result. When an extracted liquid sample is subject to partial or complete vaporization proximate to the vaporizer input, but before reaching a heated vaporization chamber, the integrity of the vaporized sample exiting a vaporizer may be compromised by undesirable partitioning of product components (lights, intermediaries, and heavies) separating and entering the vaporizer at different times. Such partitioning or separation will generally lead to faulty energy content and compositional analysis. Further, in the event that the pre-vaporized sample is exposed to subsequent cooling or pressure reduction causing re-condensation during the passage into the vaporization chamber, further undesirable compositional stratification/partitioning may result. Additionally, where pre-vaporization occurs at the vaporizer input, the cooling effect created by the expansion of the liquid to gas can generate exterior icing upstream of the entry port and thereby augment thermal anomalies which further compromise sample uniformity and integrity.
There exists a need for improvement to the presently accepted and commonly used systems and methods of vaporization of extracted natural gas samples for analysis deployable in the field, in distribution systems, and in transportation. It would be desirable to provide an improved vaporizer that ensures accurate sampling through substantially efficient, complete and uniform single pass vaporization of a liquid sample that avoids liquid pre-vaporization and downtime attributable to system damage from incomplete vaporization, particularly in the distribution, transportation, and custody transfer of natural gas.